Cement job design
DOSAS’ industry recognized subject matter experts and local cementing engineers promotes industry leading cementing solutions by integrating cutting edge product solutions and international experience. We work with our Customers to:
- Provide Well Cementing technical support to ensure zonal isolation for the life of the well
- Design primary and remedial cement jobs
- Conduct cement zonal isolation studies
- Deliver Well Cementing technical training
- Perform quality assurance audit
- Identify options and risk evaluate
- Can robust pumpable slurries be designed which can be effectively placed?
The depth of the well affects the cement slurry design because it influences the following factors:
Amount of wellbore fluids involved Volume of wellbore fluids Friction pressures Hydrostatic pressures Temperature
Wellbore depth also controls hole size and casing size. Extremely deep wells have their own distinct design challenges because of:
- High temperatures
- High pressures
- Corrosive fluids
The geometry of the wellbore is important in determining the amount of cement required for the cementing operation. Hole dimensions can be measured using a variety of methods, including:
The hole shape also determines the clearance between the casing and the wellbore. This annular space influences the effectiveness of drilling-fluid displacement. Annular clearances that are smaller restrict the flow characteristics and generally make it more difficult to displace fluids.
Another aspect of hole geometry is the deviation angle. The deviation angle influences the true vertical depth and temperatures. Highly deviated wellbores can be challenging because the casing is not as likely to be centered in the wellbore, and fluid displacement becomes difficult.
Problems created by geometry variations can be overcome by adding centralizers to the casing. Centralizers help to centre the casing within the hole, leaving equal annular space around the casing.
The temperatures of the wellbore are critical in the design of a cement job. There are basically three different temperatures to consider:
- Bottom hole circulating temperature (BHCT)
- Bottom hole static temperature (BHST)
- Temperature differential (temperature difference between the top and bottom of cement placement)
The BHCT is the temperature to which the cement will be exposed as it circulates past the bottom of the casing. The BHCT controls the time that it takes for the cement to setup (thickening time). BHCT can be measured using temperature probes that are circulated with the drilling fluid. If actual wellbore temperature cannot be determined, the BHCT can be estimated using the temperature schedules of American Petroleum Inst. (API) RP10B.1 The BHST considers a motionless condition where no fluids are circulating and cooling the wellbore. BHST plays a vital role in the strength development of the cured cement.
The temperature differential becomes a significant factor when the cement is placed over a large interval and there are significant temperature differences between the top and bottom cement locations. Because of the different temperatures, commonly, two different cement slurries may be designed to better accommodate the difference in temperatures.
The bottomhole circulating temperature affects the following:
- Slurry thickening time
- Fluid loss
- Stability (settling)
- Set time
Deepwater drilling poses unique challenges for cementing. Large-diameter casings are set in poorly consolidated formations, frequently with a narrow pore-fracture pressure window and high potential for shallow-flow hazards (water or gas). Compounding the problems is the low
temperature found at the sea bottom and the first few thousand feet below mudline. With subsea wellheads, launching cement wiper plugs is also more complicated. Logistically, the distance from shore makes versatility in cement slurry design an important consideration. Add to this the difficulty of remedial work in the deepwater environment, and annular sealing throughout the life of the well becomes more critical.
Abnormally pressured sands, with a high probability of shallow-water or gas flow, characterize many deepwater geological environments. Such flows present problems in cementing operations, affecting the integrity of the well. Consequences of uncontrolled shallow flows include
subsidence, compromised seafloor stability, loss of well support and buckling of structural casing, and compromised wellbore integrity, resulting in well control problems and potential loss of the well and supporting structures.
Primary cementing, or any workover related cementing operations such as abandoning a well, side-tracking, well control, lost circulation control.
Remedial cementing is usually done to correct problems associated with the primary cement job. The need for remedial cementing to restore a well’s issues indicates that primary operational planning and execution were ineffective, resulting in costly repair operations. Remedial cementing operations consist of two broad categories: squeeze cementing and plug cementing.
Lost circulation is a frustrating, costly and time-consuming problem. Some of the major consequences of lost circulation include increased cost resulting from:
- poor or no removal of cuttings, requiring additional wiper trips
- stuck drill pipe
- excessive mud lost
- remedial work to cure losses
- rig time required to cure losses
Reservoir damage and loss of well are also possible because of:
- lack of zonal isolation caused by poor cement coverage
- formation damage resulting from mud losses
- blowout after a drop in hydrostatic pressure.
To select the correct technique to effectively solve lost circulation, it is necessary to know the reasons for the losses; i.e., the type of loss and the drilling history. Very often lost circulation treatments fail because of a lack of information such as the types of losses and their relative depths. A lack of knowledge can lead to selection of the wrong treatment, which usually results in poor success, excessive costs and time, and the frustration caused by repetitive failures.
Lost circulation can occur at any time in the life of the well. During construction, lost circulation can be encountered while drilling and while cementing. When cement is pumped downhole, some of the cement can be lost into natural fractures, fissures, vugs or highly porous zones even when the fracture pressure is not exceeded. DOSAS’ advanced fiber cement is composed of an inert, fibrous material capable of forming a network across the loss zone, allowing circulation to be regained. The DOSAS fibers are engineered to an optimal size for sealing such loss zones.
Gas migration, or annular gas flow, is a problem that has plagued the industry for many years. There is no one cause of gas migration, nor is there any one solution to it. To effectively control gas migration, the nature of the problem must be understood so that the proper techniques can be applied. This implies a careful analysis of the potential for flow as well as an integrated approach to its control. During this analysis, one must consider not only the potentially productive intervals, but also the intervals that may not be economically productive, including gas stringers, which can exist behind any casing string.
Among the reasons for gas migration are an un-cemented channel, failure to maintain overbalance pressure before and during cementing, loss of overbalance pressure after cement placement, development of flow paths after cement setting, and insufficiently low permeability to prevent gas from flowing through the set-cement matrix. Obviously, each of these arises from different mechanisms. Therefore, control of gas migration must address the totality of the sources for flow.
Controlling gas migration takes much more than just complex cement slurry design. Slurry design addresses only one facet of the complex problem, albeit a very key one. An element of the overall process of controlling gas flow is achieving zonal isolation through the intervals containing the gas. An additional element is maintaining overbalance pressure during the critical transition period. The final element is preventing gas from migrating along the annulus.
DOSAS’ gas migration service considers these elements as three phases of the process: remove the drilling fluid to provide the proper environment for zonal isolation, delay gas entry, impede propagation of the gas. Each of these phases requires careful analysis and design to achieve the desired overall result—a well that is free of gas migration.
The first step, that of achieving zonal isolation, is accomplished by the cement, but only after the drilling fluid has been removed from the wellbore to allow cement to fully occupy the annulus between the borehole and the casing. Mud removal is accomplished by effective centralization and optimized spacer design.
The second step is to design the placement process so that an overbalanced condition is maintained until late in the transition of the cement from a liquid to a solid. The nature of the setting process makes it difficult to maintain overbalanced pressure; after placement, cement undergoes a gradual gelation, resulting in loss of hydrostatic pressure. Ideally, the pressure is maintained above formation pressure until the cement is set. In practical terms, this is extremely difficult to do. Another option is to minimize the time between development of gel strength and setting while maximizing the overbalanced pressure (without risking breaking the well down). This is done by analysing the pressures in the well and employing options that maximize the overbalanced pressure. Obviously, a component of this step is the design of the slurry.
The third step, impeding propagation of the gas, depends on the use of slurries with special properties so that gas cannot invade and migrate along the cemented annulus. Special properties, such as those provided by DOSAS’ STOPGAS slurries, are required during the critical transition period as well as after setting.